Carbon Capture, Utilization and Storage (CCUS) is one of the solutions to mitigate anthropogenic CO2 emissions. CO2 could be utilized to enhance production of shale gas. By doing so, subsurface storage of CO2 becomes economical. For instance, in the case of Utica formation, economically producible gas-in-place of 104 Trillion cubic feet (Tcf) becomes an incentive to store up to 10 Gigatonnes (Gt) of CO2 (Godec et al. 2014). The storage mechanism of nanoporous shales is highly dependent of its surface properties; 80% of the storage capacity or gas-in-place is estimated to be due to sorption of ﬂuid on the pores’ surface area (Ambrose et al. 2012). In-situ sorption capacity can be calculated from sorption measurements at elevated pressure. However, conversion of the laboratory data to storage capacity requires a prior knowledge of the nanopore structure, which is characterized by the pore volume, pore-size distribution (PSD), and speciﬁc surface area (SSA). Nanostructure of shales can be inverted from low pressure adsorption measurements. N2 adsorption at 77 K is most commonly measured for this purpose due to the availability of the gas and well-established analysis methods. The ﬁrst part of this thesis compares the continuum and statistical thermodynamics- based analysis methods applied on shales. Al though IUPAC recommends the application of statistical thermodynamics-based analysis (Thommes et al. 2015), it must be noted that resulting parameters are highly model dependent. Although none of the methods is perfectly applicable to shales, we observe systematic diﬀerences between the resulting PSD and SSA from the methods investigated. The second part of this thesis conﬁrms the need of complementing N2 results with CO2 adsorption at 273 K, particularly for the evaluation of sorption capacity of organic-rich shales. Comparison between N2 and CO2 adsorption shows that CO2 can access much smaller pores than N2. And CO2-derived SSA and pore volume is much larger than N2-derived SSA and pore volume. In contrary to the negative relationship between organic content and N2-derived SSA, we observe increasing CO2-accessible pores as a function of organic content. Our results highlight the important contribution of organic content to the shales’ CO2 storage capacity. Considering the intended application on CCUS, we have selected shale samples with various organic content from the Bakken, Niobrara, Utica and Agardhfjellet formations. The ﬁrst three formations are producing shale formations in North America, which could be candidates for CO2 enhanced hydrocarbon recovery and subsequent sequestration. Agardhfjellet formation is the analog for Draupne shale, which is the caprock overlying a CO2 storage formation in Smeaheia ﬁeld, Norway.
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